chapter 4 - appendix b

Chapter 4 – Appendix B Ameren Missouri

2011 Integrated Resource Plan

Chapter 4 - Appendix B Preliminary Screening Analysis

1

Option Description Candidate

Option

Coal Greenfield - IGCC

Coal Greenfield - IGCC with Pre-Combustion CCC

Coal Greenfield - Oxyfuel Coal with CCC

Coal Greenfield - Subcritical CFB

Coal Greenfield - Subcritical CFB with Amine-Based Post-

Combustion CCC

Coal Greenfield - Supercritical CFB

Coal Greenfield - USCPC

Coal Greenfield - USCPC with Amine-Based Post-Combustion CCC

Coal Meramec - Oxyfuel Coal with CCC

Coal Meramec - Subcritical CFB

Coal

Meramec - Ultra-Supercritical (USC) PC

Coal Meramec Repowering - CFB Boiler Replacement

Coal Meramec Repowering - Oxyfuel Coal Boiler Replacement

Coal Meramec Repowering - Unit 3 Boiler Replacement and STG

Rebuild

Coal Meramec Repowering - Unit 4 Boiler Replacement and STG

Rebuild

Coal Rush Island - Integrated Gasification Combined Cycle (IGCC)

Coal Rush Island - Oxyfuel Coal with CCC

Coal Rush Island - Subcritical CFB

Coal Rush Island - USCPC

Coal Efficiency Improvements to Existing Plants – Condenser Back-

pressure Reductions

Coal Efficiency Improvements to Existing Plants – Duct Draft

Reductions

Gas Goose Creek - Inlet Chilling SCCT Power Augmentation

Gas Goose Creek - Wetted Media SCCT Power Augmentation

Gas Greenfield - 2-on-1 501F CCCT

Gas Greenfield – 2-on-1 Wartsila 20V34SG Combined Cycle

Reciprocating Engine

Gas Greenfield - CCCT Amine-Based Post-Combustion CCC

Gas Greenfield – GE 7EA Cheng Cycle

Gas Greenfield - Molten Carbonate Fuel Cell

Gas Greenfield - Natural Gas Fueled Rankine Cycle

Gas Greenfield - Twelve Wartsila 20V34SG Simple Cycle

Reciprocating Engines

Gas Greenfield - Two 501F SCCTs (10% CF)

1 4 CSR 240-22.040(1)

Ameren Missouri Chapter 4 – Appendix B


Option Description Candidate

Option

Gas Greenfield - Two 501F SCCTs (5% CF)

Gas Meramec - 2-on-1 501F CCCT

Gas Meramec Repowering - Unit 3 & Unit 4 STGs in a Shared CCCT

Conversion

Gas Meramec Repowering - Unit 3 & Unit 4 STGs in Separate CCCT

Conversions

Gas Meramec Repowering - Unit 3 Boiler NG Conversion

Gas Meramec Repowering - Unit 4 Boiler NG Conversion

Gas Meramec Repowering - Unit 4 STG in a 3-on-1 CCCT

Conversion

Gas Mexico - One GE LM6000 Sprint SCCT (10% CF)

Gas Mexico - One GE LM6000 Sprint SCCT (5% CF)

Gas Raccoon Creek - One GE 7EA SCCT (10% CF)

Gas Raccoon Creek - One GE 7EA SCCT (5% CF)

Gas Venice - 2-on-1 501F CCCT Conversion

4.1 Technology Characterization

Following the high-level fatal flaw analysis and elimination of several options, the list of

options to be evaluated as part of the second stage of the screening analysis was

reduced. Cost, performance, and operating characteristics were developed for each of

the remaining options in support of the Preliminary Screening with input from Ameren

Missouri and Black & Veatch‟s internal resources.

All performance and cost estimates were based on technologies fueled by the following

design fuels2:

Coal - All coal-fueled options are characterized such that they can operate on

either 100 percent Powder River Basin (PRB) coal or 100 percent Illinois Basin

No. 6 coal (or on any combination of the two). Thermal performance and

emissions estimates for the coal-fueled options assume 100 percent of the

feedstock is PRB coal. The air quality control systems (AQCS) for coal-fueled

options were selected to achieve target emissions limits for either coal assuming

representative fuel properties for Illinois Basin No. 6 coal.

Natural Gas - All gas-fueled options would be designed to operate on pipeline

quality natural gas, assumed to be 100 percent methane with 0.2 grain of sulfur

per 100 standard cubic feet, unless specified otherwise.

4.1.1 Capacity Ranges

Each of the generation technologies identified in the evaluated options list has sizing

limitations. The selection of practical size ranges for each of the technologies is based

2 4 CSR 240-22.040(1)(A)



on Ameren Missouri‟s ability to plan for and reasonably implement the technology.

Table 4.B.1 provides a summary of approximate size limitations for new generation

units3.

Table 4.B.1 Capacity Ranges

Full load thermal performance and emissions were developed for all evaluated options.

Thermal performance was estimated for a 95° F day and a 20° F day. Site conditions

were selected to reflect Ameren Missouri‟s service area. The following elevation and

ambient conditions were assumed for all performance estimates:

Elevation--500 feet above mean sea level.

20° F day ambient conditions:

o Dry bulb temperature--20° F.

o Relative humidity--60 percent.

95° F day ambient conditions:

o Dry bulb temperature--95° F.

o Relative humidity--60 percent.

Capacity and performance data for each evaluated option are presented in Table 4.B.12

and Table 4.B.13 under the Supporting Tables section.

4.1.2 Commercial Availability

The commercial status of each of the evaluated technologies was qualitatively

assessed. Technology maturity was assessed as either “mature” or “developing.”

3 4 CSR 240-22.040(1)(B)



Technologies defined as mature were those that are proven and well established within

the electric power generation industry. Developing technologies consist of all other

technologies that may have limited experience, have been utilized in demonstration

projects, or consist of laboratory-tested conceptual designs.

4.1.3 Capital Cost Estimates

Screening level, overnight EPC capital cost estimates were developed for all evaluated

options and expressed in 2009 dollars. The values presented are reasonable for today‟s

market conditions, but, as demonstrated in recent years, the market is dynamic and

unpredictable. Power plant costs are subject to continued volatility and the estimates in

this report should be considered primarily for comparative purposes. The EPC costs

presented in this report were developed in a consistent manner and are reasonable

relative to one another.

The EPC estimates include costs for equipment and materials, construction labor,

engineering services, construction management, indirects, and other costs on an

overnight basis and are representative of “inside the fence” project scope. The

estimates were developed using Black & Veatch proprietary estimating templates and

experience. The overall capital cost estimates consist of three main components: EPC

Capital Cost, Owner‟s Cost (excluding AFUDC [Allowance for Funds Used during

Construction]), and Owner‟s AFUDC Cost. Capital costs for all evaluated options are

presented in Table 4.B.14 and Table 4.B.15.

An allowance has been made for Owner‟s costs (excluding AFUDC). Items included in

the Owner‟s costs include “outside the fence” physical assets, project development, and

project financing costs. These costs can vary significantly, depending upon technology

and unique project requirements. Black & Veatch has developed Owner‟s costs as a

percentage of the EPC capital cost as shown in the tables referenced above. Owner‟s

costs are assumed to include project development costs, interconnection costs, spare

parts and plant equipment, project management costs, plant startup/construction

support costs, taxes/advisory fees/legal costs, contingency, financing and

miscellaneous costs. Table 4.B.2 shows a more detailed explanation of potential

owner‟s costs.

For the purposes of characterizing all of the evaluated options, the AFUDC was

calculated by applying the Present Worth Discount Rate (PWDR) over half of the

construction duration, with the construction duration being defined as the time period

from Notice to Proceed (NTP) to Commercial Operation Date (COD).



Table 4.B.2 Potential Items for Owner’s Costs4

Project Development:

Site selection study

Land purchase/options/rezoning

Transmission/gas pipeline rights of way

Road modifications/upgrades

Demolition (if applicable)

Environmental permitting/offsets

Public relations/community development

Legal assistance

Utility Interconnections:

Natural gas service (if applicable)

Gas system upgrades (if applicable)

Electrical transmission

Supply water

Wastewater/sewer (if applicable)

Spare Parts and Plant Equipment:

Air quality control systems materials, supplies,

and parts

Acid gas treating materials, supplies and parts

Combustion turbine and steam turbine materials,

supplies, and parts

HRSG materials, supplies, and parts

Gasifier materials, supplies, and parts

Balance-of-plant equipment materials, supplies

and parts

Rolling stock

Plant furnishings and supplies

Operating spares

Owner’s Project Management:

Preparation of bid documents and selection of

contractor(s) and suppliers

Provision of project management

Performance of engineering due diligence

Provision of personnel for site construction

management

Plant Startup/Construction Support:

Owner‟s site mobilization

O&M staff training

Supply of trained operators to support equipment

testing and commissioning

Initial test fluids and lubricants

Initial inventory of chemicals/reagents

Consumables

Cost of fuel not recovered in power sales

Auxiliary power purchase

Construction all-risk insurance

Acceptance testing

Taxes/Advisory Fees/Legal:

Taxes

Market and environmental consultants

Owner‟s legal expenses:

• Power Purchase Agreement (PPA)

• Interconnect agreements

• Contracts--procurement & construction

• Property transfer

Owner’s Contingency:

Owner‟s uncertainty and costs pending final

negotiation:

• Unidentified project scope increases

• Unidentified project requirements

• Costs pending final agreement (e.g.,

interconnection contract costs)

Financing:

Development of financing sufficient to meet project

obligations or obtaining alternate sources of

funding

Financial advisor, lender‟s legal, market analyst,

and engineer

Interest during construction

Loan administration and commitment fees

Debt service reserve fund

Miscellaneous:

All costs for above-mentioned Contractor-excluded

items, if applicable

4 4 CSR 240-22.040(3); 4 CSR 240-22.040(6)



4.1.4 Non-Fuel O&M Costs

Nonfuel O&M cost estimates were developed for each of the evaluated options. All

O&M cost estimates are presented in Table 4.B.14 and Table 4.B.15. First year O&M

costs (in 2009 $‟s) were estimated, and for the future years 3% escalation rate was

used.

The modes of dispatch used to establish maintenance intervals for many of the options

are as follows:

Baseload Dispatch Profiles – Excluding the IGCC options, all options evaluated at a

baseload dispatch mode were assumed to operate at full load at a capacity factor of 85

percent. An IGCC facility is not anticipated to be capable of operating at such a high

capacity factor because of the degree of process integration. All IGCC options were

assumed to operate at full load at a capacity factor of 80 percent. Options incorporating

Carbon Capture and Compression (CCC) were assumed to operate at the same

dispatch profile as their non-carbon capture counterparts.

Intermediate Load Dispatch Profiles – Two operating profiles were used for the

intermediate load technologies.

Profile 1 – Cycling Operation – Off Nights/Off Weekends: 6 months per year

operation at 5 days a week, 8 hours per day in 2x1 combined cycle mode, off-line

16 hours per day and on weekends. Shut down and laid up for 6 winter months

per year. Total full load operation of 1,043 hours per year and a capacity factor of

about 12 percent.

Profile 2 – Cycling Operation – Low Load Nights/Off Weekends: 6 months

per year at 5 days a week, 10 hours per day in 2x1 combined cycle mode, 14

hours per day in 1x1 combined cycle mode at minimum load on the steam

turbine, shut down on weekends. Shut down and laid up for 6 winter months per

year. This equates to a capacity factor of about 21 percent for the options

evaluated in this study.

Peaking Load Dispatch Profiles – All new unit combustion turbine options were

evaluated at a peaking dispatch mode, with capacity factors of 5 and 10 percent. It was

assumed that 90 starts were associated with a 5 percent capacity factor and 150 starts

with a 10 percent capacity factor.

Power augmentation and reciprocating engines operating in simple cycle were

evaluated at a 5 percent capacity factor.



4.1.5 Scheduled and Forced Outages

Scheduled maintenance intervals were obtained from original equipment manufacturers

(OEMs) or estimated on the basis of Black & Veatch experience for each of the

technologies. Where information was not available, maintenance intervals were

estimated using data gathered from comparable technologies. These scheduled

maintenance patterns were assumed to be the same for technologies employing CCC

equipment. The maintenance patterns are presented in Table 4.B.3.

Table 4.B.3 Scheduled Maintenance Outage Patterns5

Notes:

(1) 4 week boiler outage every 18 months and a 6 week STG major outage every 6 years.


(3) Alternating 1 week and 3 week combined cycle outages yearly, alternating 3 week and 2 week

gasification outages yearly and a 4 week combined cycle outage every 6 years. This schedule is

representative of planned maintenance beginning in year 4. Longer gasification outage durations are

expected for years 1 through 3.


(5) Siemens recommends the following: 1 week combustion inspection every 8,333 eq. hours, 2 week hot

gas path inspection every 25,000 eq. hours, and a 4 week major inspection every 50,000 eq. hours for

the combustion turbine. A 6 week major outage is recommended at 50,000 eq. hours for the STG.

(6) Short outages required every 2,000 to 3,000 hours of operation.

(7) 2 week per 8,000 hours, 3 weeks per 16,000 hours, and 4 weeks per 48,000 hours.

5 4 CSR 240-22.040(1)(G)



(8) GE recommends the following: 1 week combustion inspection every 450 starts, 2 week hot gas path

inspection every 1,200 starts, and a 4 week major inspection every 2,400 starts.

(9) Siemens recommends the following: 1 week combustion inspection every 450 starts, 2 week hot gas

path inspection every 900 starts, and a 4 week major inspection every 1,800 starts.

(10) GE recommends the following: 1 week hot section rotable exchange every 25,000 hours and a 10

week (nominal) engine overhaul every 50,000 hours.

Where available, generic equivalent forced outage rate (EFOR) and equivalent demand

forced outage rate (EFORd) data were gathered for each of the technologies. The

EFOR and EFORd data are presented in Table 4.B.4. The information was taken from

the NERC GADS database and published literature to the extent that data were

available. When information was not available, values were estimated using data

gathered from comparable technologies. EFOR and EFORd were not estimated for

technologies employing CCC equipment. For this effort and at this stage of planning, it

is assumed that the availability of CCC equipment is independent of the generating

facility availability and does not affect EFOR and EFORd. The information is generic,

but representative for screening-level supply-side resource analyses.

Table 4.B.4 Forced Outage Rates6

6 4 CSR 240-22.040(1)(I)



4.1.6 Waste Generation

Wastewater and waste solids must be processed and properly disposed. Technologies

fueled by natural gas produce negligible solid waste, but can produce wastewater

streams. Coal-fueled technologies produce both wastewater and waste solids. Table

4.B.5 presents a summary of the production of wastewater and solid wastes for the

evaluated options.

Table 4.B.5 Waste Generation7

4.1.7 Potentially Useable Byproducts

A variety of solid materials may be generated from the combustion and gasification of

coal, including fly ash, bottom ash, byproducts from FGD operation, and byproducts

from coal gasification.

7 4 CSR 240-22.040(1)(K)2



Fly Ash – The most widely known uses for fly ash are in the cement and concrete

industries. Fly ash has been used extensively for many civil engineering

purposes, including structural fill, flowable fill, and road base materials. The use

of fly ash is prevalent in road projects where large quantities of suitable soils may

not be available. Fly ash has been blended with hydrated lime and aggregated

materials to form road base materials that are stronger and more durable than

conventional crushed stone or gravel base. Other applications include mineral

fillers, mining applications, and agricultural uses.

Bottom Ash – Bottom ash is widely utilized in road bases and structural fill

projects. Other applications include use as a sand substitute in cement concrete

mixtures, surface material on composition roof shingles, and as an antiskid

material applied to roadways in the northeast part of the country.

FGD Byproducts – The primary factor affecting the type of byproduct from lime or

limestone-based wet scrubbers is the degree to which oxidation has taken place

within the FGD system. If oxidation is promoted, the byproduct will be primarily in

the form of calcium sulfate or FGD gypsum. If oxidation is not promoted, much of

the product will remain in the calcium sulfite form. In general, FGD gypsum is the

more desirable product because it is relatively easy to dewater and can be sold

in a variety of re-use markets, such as wallboard production. The minimum purity

requirement in the utility industry for marketing FGD gypsum is typically 95

percent or greater.

FGD gypsum is also commonly used in the cement industry. FGD gypsum is

used to replace natural gypsum as one of the final steps in the cement

manufacturing process. As with wallboard, the gypsum must be free from

contamination and consistent in composition. FGD gypsum has also been used

successfully as an engineered material in structural fills and road bases. Gypsum

is commonly used as an agricultural additive for soils deficient in calcium and

sulfur. The use of FGD gypsum as a substitute for natural gypsum in agricultural

applications is somewhat more flexible than in wallboard and cement

manufacture because less stringent specifications on sulfite, ash, and chloride

content can be tolerated.

Coal Gasification Byproducts – The IGCC technology evaluated in this study

employs a Claus sulfur recovery plant from which liquid elemental sulfur is

recovered. This sulfur is commonly used in a variety of industries such as the

rubber industry, fertilizer manufacturing, oil refining, wastewater processing, and

mineral extraction. The gasifier produces a molten slag that flows freely into a

water-filled compartment at the bottom of the gasifier. As the molten slag

contacts the water bath, the slag vitrifies into dense, glassy granules. The vitrified



slag produced by the gasifiers can be used for the fabrication of ceramic

products.

4.1.8 Coal Technology Options

Ultra-Supercritical (USC) Pulverized Coal (PC)

The following assumptions have been made for all ultra-supercritical PC options:

1. Single unit site, with a capacity of 900 MW net (nominal).

2. USC TC4F STG and USC PC boiler.

3. AQCS:

• Low nitrogen oxide (NOx) burners and selective catalytic reduction (SCR) for

nitrogen oxides (NOx) control.

• Wet flue gas desulfurization (FGD) for sulfur dioxide (SO2) control.

• Activated carbon injection for mercury control.

• Pulse-jet fabric filter for particulate matter (PM10) control.

• Sorbent injection for sulfur trioxide (SO3) control.

4. Turbine driven boiler feed pumps.

5. Throttle conditions – 3,800 psia (pounds per square inch absolute)/1,110° F main

steam/1,110° F reheat.

6. Single reheat steam cycle.

7. Eight feedwater heaters – Three high-pressure (HP), four low-pressure (LP), and one

deaerator (DA).

8. Ultra-supercritical PC options that employ carbon dioxide (CO2) capture and

compression (CCC) would utilize an amine-based chemical solvent to remove 90

percent of the CO2 from the flue gas stream. Staged compression would deliver the CO2

to the site boundary at a pressure of 2,200 psig (pounds per square inch gauge). CO2

transportation and sequestration are evaluated separately.

Oxyfuel Coal

The following assumptions have been made for all oxyfuel coal options:

1. Single unit site, with a fuel flow rate equal to the fuel flow rate for the ultra-

supercritical PC plant (Refer to Section 3.2.1).

2. USC TC4F STG and USC PC boiler.

3. AQCS:

• Low NOx burners and SCR for NOx control.

• Wet FGD for SO2 control.


• Pulse-jet fabric filter for particulate control.

• Sorbent injection for SO3 control.



• 90 percent of the flue stream would be compressed and delivered to the site

boundary at a pressure of 2,200 psig. CO2 transportation and sequestration are

evaluated separately.

4. Flue gas recycle.

5. Air Separation Unit (ASU) – 95 percent oxygen (O2) purity.

6. Turbine driven boiler feed pumps.

7. Throttle conditions – 3,800 psia/1,110° F/1,110° F.


9. Eight feedwater heaters – Three HP, four LP, and one DA.

Circulating Fluidized Bed (CFB)

The following assumptions have been made for all CFB options:

1. Single unit site, with a capacity of 2 x 300 MW net (nominal) boilers and 1 x 600 MW

net (nominal) TC4F STG.

2. AQCS:

• Combustion controls and selective noncatalytic reduction (SNCR) for NOx

control

• Boiler limestone injection and polishing spray dry absorber for polishing

SO2/SO3 control.


• Pulse-jet fabric filter for particulate control.

3. Motor driven boiler feed pumps.


5. Eight feedwater heaters – Three HP, four LP, and one DA.

6. A mechanical-draft, counterflow, cooling tower assumed for heat rejection.

7. CFB options that employ CCC would utilize an amine-based chemical solvent to

remove 90 percent of the CO2 from the flue gas stream. Staged compression would

deliver the CO2 to the site boundary at a pressure of 2,200 psig. CO2 transportation and

sequestration are evaluated separately.

Subcritical CFB

1. Subcritical STG and subcritical CFB boilers.


Supercritical CFB

1. Supercritical STG and supercritical CFB boilers.




Integrated Gasification Combined Cycle (IGCC)

The following assumptions have been made for all integrated gasification combined

cycle (IGCC) options:

1. Two 50 percent dry fed, entrained-flow Shell Coal Gasification Process gasifiers.

2. Two General Electric (GE) 7FB8 combustion turbine generators (CTGs) with syngas

combustors.

3. Two 50 percent ASUs – 95 percent O2 purity.

4. One subcritical TC2F STG.

5. Two triple-pressure heat recovery steam generators (HRSGs).

6. AQCS:

• Nitrogen diluent, syngas saturation, and SCR for NOx control.

• Carbonyl sulfide (COS) hydrolysis, Selexol acid gas removal

(AGR), and Claus sulfur recovery unit (SRU) with tailgas recycle for SO2 control

and sulfur recovery.

• Candle filter for particulate control.

• Sulfided carbon bed adsorption for mercury control.

7. Inlet air evaporative cooling above 59° F.


9. No duct firing for the HRSG(s).

10. IGCC options that employ CCC would utilize a Genosorb physical solvent CO2

removal process to remove 90 percent of the CO2 from the syngas stream. Rather than

a Selexol process, options that employ CCC would utilize an MDEA (methyl

diethanolamine) acid gas removal process. Staged compression would deliver the CO2

to the site boundary at a pressure of 2,200 psig. CO2 transportation and sequestration

are evaluated separately.

Efficiency Improvements – Duct Draft Reductions9

The electrical auxiliary loads required to drive the forced draft (FD) and induced draft

(ID) fans are significant in a PC plant. Any reductions in air handling system pressure

loss will reduce the required auxiliary loads and, therefore, increase the net plant output

(NPO).

One method of calculating reduced pressure loss potential in the air handling system is

to perform cold flow modeling. According to Pollution Control Services, Inc. (PCS),

implementing modifications identified from modeling flows from the boiler economizer

through the SCR, air heater, ESP/baghouse, scrubber, ID fans and stack will typically

result in overall static loss reductions of 3 to 8 inches of water column (in-wc). Using the

information provided by PCS, Black & Veatch made a conservative assumption that five

8 Future offerings will be presented as “7FA Syngas.”

9 4 CSR 240-22.040(4)



flow correction devices could be installed in each Ameren Missouri PC unit. Flow

correction devices attempt to restrict or divert the flows in an attempt to achieve more

uniform flow distribution and lower pressure drop. Some examples of flow correction

devices include turning vanes, splitters, egg crates, and perforated plates.

Assuming an average static loss reduction of 0.4 in-wc per flow correction device results

in an overall pressure loss reduction of 2.0 in-wc per unit. A reduction in pressure loss

would result in auxiliary load savings through the ID fan(s), increasing net output. Using

Ameren Missouri unit operating data, Black & Veatch estimated ID fan auxiliary load

savings for a 2.0 in-wc pressure drop reduction for Rush Island Unit 2. The performance

gains realized at Rush Island Unit 2 are representative of a ~ 600 MW pulverized coal

unit.

An order-of-magnitude capital cost estimate was developed using information provided

by PCS and recent Black & Veatch experience with such flow correction devices. PCS

suggested budget cost of $400,000 to $500,000 for 1:12 scale cold flow modeling of

Rush Island Units 1 and 2. Translated roughly, this equates to about $250,000 for cold

flow modeling at Rush Island Unit 2 only. Recent installations of flow correction devices

in nominal 500 MW – 600 MW pulverized coal plants have ranged in cost from

approximately $40,000 to $65,000 per flow correction device. With the fixed expense of

cold flow modeling, modifications made to the larger units will most likely be the most

economical.

Efficiency Improvements – Condenser Back-Pressure Reductions10

The performance of a condenser impacts STG performance, thereby, affecting unit

performance. Unit performance can be improved by increasing the condenser

cleanliness factors for plants utilizing once-through cooling systems. Debris filters can

reduce macro fouling and tubesheet pluggage in the condenser. Two types of debris

filters may be applied:

In-line debris filter – placed in the circulating water pipe near the condenser

waterbox.

Intake debris filter – placed at the intake structure and intended to replace the

traveling screens.

Costs for intake debris filters were developed for this analysis. The capital cost

requirements are greater for intake debris filters than for in-line debris filters. However,

with the implementation of in-line debris filters, it is recommended that traveling screens

remain in service. Traveling screens tend to have significant problems with carryover of

debris and are maintenance intensive. Intake debris filters are intended to replace

10

4 CSR 240-22.040(4)



traveling screens, likely reducing total system maintenance requirements and improving

overall unit reliability.

Black & Veatch believes that implementation of a condenser ball cleaning system, in

conjunction with debris filters, is the best approach to realizing significant condenser

performance improvements.

Black & Veatch spoke with Ameren Missouri engineers and utilized on-line Ameren

Missouri unit operating data and equipment design information to develop a

performance impact estimate for Rush Island Unit 2. A cost estimate for the intake

debris filters and condenser ball cleaning systems was developed from multiple vendor

budgetary quotations. The performance impact estimate represents average condenser

cleanliness factor increases of 25 percentage points for each hour Rush Island Unit 2

would operate above the design condenser backpressure assuming an existing

condenser cleanliness factor of 60 percent. The performance and cost estimates for

Rush Island Unit 2 are representative of a ~ 600 MW pulverized coal unit.

4.1.9 Natural Gas Technology Options

Meramec Unit 4 STG in Combined Cycle Conversion

The reuse of Unit 4‟s STG as part of a combined cycle was included as an alternative to

replacing Units 1 through 4 with an entirely new unit at Meramec. Reuse of the Unit 4

STG would entail the addition of three CTGs, each fitted with a Heat Recovery Steam

Generator (HRSG). Steam produced in the HRSGs would be sent to the Unit 4 STG.

Each of the HRSGs would be outfitted with duct firing to fully utilize the STG capacity.

The following assumptions have been made for the Meramec Unit 4 STG combined

cycle conversion option:

1. Three Siemens 501F CTGs and three HRSGs supplying steam to the existing Unit 4

STG.

2. AQCS:

• Dry low NOx burners and SCR for NOx control.

• CO oxidation catalyst for carbon monoxide (CO) and volatile organic

compounds (VOC) controls.


4. Duct firing during hot day conditions to match the design limits of the Unit 4 STG.

5. Triple-pressure HRSGs.

6. No HRSG bypass dampers and stacks included.

7. Existing equipment removed from service:

• Unit 4 boiler.

• Unit 4 feedwater heaters.

• Unit 4 boiler feed pump(s).

• Existing Unit 4 feedwater and steam piping.



• Plant control system.

• Unit 4 electrostatic precipitator (ESP).

• Unit 4 coal and limestone handling equipment.

• Units 1 through 3 in their entirety.

8. Equipment reused in combined cycle conversion:

• Unit 4 STG.

• Unit 4 STG control system.

• Unit 4 gland steam condenser.

• Unit 4 gland steam regulator.

• Unit 4 condenser.

9. Scope of work needed to refurbish reused equipment:

• STG intermediate pressure (IP) retrofit.

• STG high pressure (HP) stator rewind and rotor replacement.

• STG low pressure (LP) stator rewind and rotor replacement.

• STG static excitation retrofit.

• Condenser retubing.

Meramec Boiler Conversion to Natural Gas

The following scope of work applies to the Meramec Unit 3 and 4 options in which the

boilers would be converted to burn natural gas:

1. Burner replacement.

2. Reheater modifications.

3. Superheater modifications.

4. Desuperheater spray modifications.

5. Air heater modifications.

6. Boiler controls modifications.

Meramec Boiler Replacements and STG Rebuilds

The following scope of work applies to the Meramec Unit 3 and 4 options in which the

boilers would be replaced and the STG sets would be refurbished:

1. Boiler - New waterwalls.

2. Boiler - Major superheater and reheater retrofits.

3. Steam piping modifications (main steam, cold reheat, and hot reheat).

4. Feedwater system modifications.

5. Hot well pump overhaul.

6. DA replacement (excluding DA storage tank).

7. One feedwater heater replacement.

8. Condenser retubing.

9. Induced draft fan motor and rotor modifications.

10. Water cannon replacement.



11. Unit-specific bottom ash system.

12. Fly ash collection system.

13. Significant structural steel modifications.

14. Demolition.

15. STG intermediate pressure (IP) retrofit.

16. STG high pressure (HP) stator rewind and rotor replacement.

17. STG low pressure (LP) stator rewind and rotor replacement.

18. STG static excitation retrofit.

Combined Cycle

Performance, emissions, and cost estimates were prepared for the following combined

cycle technology:

• 2-on-1 Siemens combined cycle based on a Siemens 501F CTG.

The following assumptions have been made for all combined cycle options:

1. Two CTGs, two HRSGs, and one TC2F STG.

2. AQCS:

• Dry low NOx burners and SCR for NOx control.

• CO oxidation catalyst for CO and VOC controls.


4. Duct firing during hot day conditions to match 600 MW net plant output.

5. Triple-pressure HRSGs.


7. No HRSG bypass dampers and stacks.

8. Combined cycle options that employ CCC would utilize an amine-based chemical

solvent to remove 90 percent of the CO2 from the flue gas stream. Staged compression

would deliver the CO2 to the site boundary at a pressure of 2,200 psig. CO2

transportation and sequestration are evaluated separately.

Venice Combined Cycle Conversion

Performance, emissions, and cost estimates were developed as part of a separate

study conducted by Black & Veatch for Ameren Missouri. The conversion of Venice

units 3 and 4 from two Siemens Westinghouse 501F combustion turbines to a 2-on-1

combined cycle required the following additional systems:

• Two HRSGs and one TC2F STG.

• Duct firing during hot day conditions to match the 600 MW net plant output.

• Triple-pressure HRSGs.

• A mechanical-draft, plume abated cooling tower assumed for heat rejection.



The conversion of two simple cycle combustion turbines into a 2-on-1 combined cycle

block represents a net capacity increase. In addition, the combined cycle would likely be

dispatched more frequently than the current simple cycles, resulting in a net increase in

fuel consumption and operations expenses. For screening purposes, the Venice

combined cycle conversion option is treated as an incremental capacity increase to

exiting Venice Units 3 and 4 with fuel burn rate and fixed and non-fuel variable O&M

estimates equal to the entire 2-on-1 combined cycle block. For modeling purposes, the

Venice combined cycle conversion is treated as a 2-on-1 combined cycle block. All

model runs with the Venice combined cycle block exclude the existing Unit 3 and 4

simple cycles. All model runs with the existing Unit 3 and 4 simple cycles exclude the

Venice combined cycle block.

Fuel Cell

Performance, emissions, and cost estimates were prepared for the following fuel cell

technology:

• Generic, molten carbonate fuel cells.

The following assumptions have been made for the gas-fueled fuel cell facility:

1. Thirty-six (36) 2.8 MW (net, nominal) fuel cell packages.

Combined Cycle Reciprocating Engines

Performance, emissions, and cost estimates were prepared for the following

reciprocating engine technology:

• Wärtsilä 20V34SG

The following assumptions have been made for the gas-fueled combined cycle

reciprocating engine facility:

1. NOx reduction would be achieved through use of a urea-based SCR system located

in the HRSGs.

2. The power block would consist of two 20V34SG engines, one nonreheat STG, and

two HRSGs.

3. A mechanical-draft, counterflow cooling tower would be included.

Cheng Cycle


combustion turbine technology:

• GE 7EA

The following assumptions have been made for the gas-fueled Cheng Cycle facility:



1. The power block would consist of one modified GE 7EA CTG and one HRSG.

2. Emissions would be controlled through the use of Cheng Low NOx (CLN) combustion

with steam/fuel premixing.

3. Power augmentation would be achieved through use of the Advanced Cheng System

(ACS) and Cheng Boost steam injection.

Simple Cycle

Performance, emissions, and cost estimates were prepared for the following simple

cycle technologies:

• Large Frame – Siemens 501F.

• Small Frame – GE 7EA.

• Aeroderivative – GE LM6000 SPRINT.

The following assumptions have been made for all simple cycle options:

1. Dry low NOx (DLN) burners would be included for NOx control.

2. Units that are dispatched at a capacity factor of 5 percent would not include an SCR

system or CO oxidation catalyst.

3. Units that are dispatched at a capacity factor of 10 percent would include an SCR

system and CO oxidation catalyst.

Existing Simple Cycle Fleet Power Augmentation11

Characteristics for simple cycle power augmentation options were developed as part of

a separate study conducted by Black and Veatch. The objective of this study was to

identify a single preferred power augmentation technology for the block of turbines

located at each facility. The study considered the following commercially available

power augmentation technologies:

Wetted Media Evaporative Cooling.

Inlet Fogging Evaporative Cooling.

Wet Compression.

Inlet Chilling.

Inlet Chilling with Thermal Storage.

Water Injection.

Steam Injection.

GE SPRINT Package.

In total, 38 CTs distributed among seven sites were analyzed to determine the feasibility

of installing various commercially available power augmentation technologies. The

results of the power augmentation technology screening are presented in Table 4.B.6.

11

4 CSR 240-22.040(4)



Table 4.B.6 CTG Power Augmentation Summary of Results

The two options included from that study were selected on the basis of cost of power

and capacity addition potential. The first option selected is the addition of wetted media

(commonly referred to as evaporative cooling) to six GE 7EA combustion turbines at

Ameren Missouri‟s Goose Creek facility. The second option selected is the addition of

inlet chilling to the 7EAs at Goose Creek. The first power augmentation option offers the

lowest cost on a dollar per kW basis at $150/kW with 3MW capacity increase on each of

the six units. However, the second option offers a more substantial capacity increase- a

total increase of 66 MW, but at a higher cost- $600/MW.

Reciprocating Engines (Simple Cycle)


reciprocating engine technology:

• Wärtsilä 20V34SG

The following assumptions have been made for the gas-fueled reciprocating engine

facility:

1. Units would be dispatched at a low capacity factor that would preclude SCR.

2. The power block would consist of twelve 20V34SG engines, for a 100 MW net

(nominal) output.

No additional operational characteristics, constraints or siting impacts that could affect

the screening results were identified. By the same token, no other technology



characteristics were identified that may make the technology particularly appropriate as

a contingency option under extreme outcomes.12

4.2 Preliminary Screening Analysis

Preliminary Screening Methodology

After each evaluated option was characterized, each was subjected to a preliminary

screening analysis. The preliminary screening analysis provided an initial ranking of the

technologies. A scoring methodology was developed to compare the different options

within their fuel group by an overall weighted score. This score was developed for each

option by comparing the following categories: levelized cost of energy, environmental

cost, risk reduction, planning flexibility, and operability. Criteria within those categories

were established, and numerical scores were assigned on the basis of the

differentiating qualitative technology characteristics. Criteria were established on the

basis of Black & Veatch‟s experience with consideration of Ameren Missouri‟s known

planning requirements. Categories and criteria, along with their assigned weightings,

are presented in Table 4.B.7.13

12

4 CSR 240-22.040(1)(J); 4 CSR 240-22.040(1)(K)4; 4 CSR 240-22.040(1)(L) 13

4 CSR 240-22.040(2)



Table 4.B.7 Scoring Criteria



Risk Reduction – The scoring of the various options took the amount of risk associated

with development and operations into account. An option‟s commercial status,

constructability, and potential hazards were all evaluated.

Planning Flexibility – The time required to construct a resource option, the fuels an

option could burn to produce electricity, and Ameren Missouri‟s ability to properly plan

and integrate an option into its current service network were evaluated for this category.

Operability – An option‟s availability, load-following capability, and complexity of

operation were reviewed and scored accordingly.

Environmental Cost14 – A resource option‟s ability to meet current and potential future

environmental regulations was incorporated into the ranking process. Emissions

constituents considered for this category include, but are not limited to, CO2, particulate

matter, sulfur oxides (SOx), NOx, Hg, and CO. A schedule of emission costs used in the

utility cost estimates for screening is presented in Table 4.B.8.

Table 4.B.8 Emissions Costs and Escalation Rates

It was assumed that new resources would be required to meet more stringent

environmental regulations and, therefore, would not incur any additional mitigation

costs. For example, any new coal unit would include a scrubber for SO2, an SCR for

NOx, activated carbon injection for mercury, and in some cases carbon capture and

compression technology. Also, new natural gas units are assumed to include an SCR

for NOx control.

The scenarios described in Chapter 2 include alternative carbon regulation regimes,

including: „Cap-and-Trade‟, „Federal Energy Bill‟, and „Moderate EPA Regulation‟, with

33%, 57% and 10% probabilities, respectively, assigned in the probability tree. CAIR

and CAMR were modeled in the scenarios developed in Chapter 2 for SO2, NOx, and

Mercury regulations. It was assumed that new units would require Mercury reductions

of 60% by 2015 and 90% by 2020. As described in Chapter 2, the NOx and SO2 prices

vary by scenarios as they are sensitive to carbon policy and other aspects of the

scenarios. All candidate resource options will be evaluated against the scenarios

developed in Chapter 2.

14

4 CSR 240-22.040(2)(B); 4 CSR 240-22.040(2)(B)1; 4 CSR 240-22.040(2)(B)2; 4 CSR 240-22.040(2)(B)3; 4 CSR 240-22.040(2)(B)4; 4 CSR 240-22.040(9)(D)

SO2 NOx CO2

2009 $/ton $25.59 $430.82 $17.17

Escalation 3.00% 3.00% 7.45%

SourceCRA Study

6/2/09

Chicago Climate Fund

Exchange - issued 4/27/09



At this point in the analysis Ameren Missouri is not screening any of its existing

resources. However, Chapter 8 describes two additional environmental scenarios to

better characterize the effects of more stringent environmental regulations on existing

Ameren Missouri generation resources, namely its coal assets. Furthermore, those

additional environmental scenarios facilitate the retirement analysis of Meramec plant.

Levelized Cost of Energy – One of the more significant criteria in the scoring was the

levelized cost of energy (LCOE). Financial factors, such as fuel costs, tax life, economic

life, escalation rates, present worth discount rate (PWDR), levelized fixed charge rate

(LFCR) that were used in the LCOE estimates in the screening in addition to other costs

presented earlier are listed in Table 4.B.9 and Table 4.B.10.

Table 4.B.9 Fuel Prices for LCOE Estimates

Table 4.B.10 Financial Inputs for LCOE Estimates

Annual costs for the LCOE estimates include levelized annual capital cost, fixed and

variable O&M, fuel cost, and emissions allowances if applicable; LCOE estimates were

developed in three different ways: without emission costs, with emissions costs for SO2

and NOx, and with emissions costs for SO2, NOx and CO2.15

15

4 CSR 240-22.040(2)(A)

LocationMeramec/

Rush

Meramec/

RushGreenfield Greenfield Greenfield

Type PRB Coal IL Coal PRB Coal IL Coal Natural Gas

2009 $/MMBtu $2.10 $2.86 $2.47 $3.03 $6.09

Escalation 3.81% 3.21% 3.84% 3.26% 2.71%

SourceAFS Nat Gas

Forecast 4/28/09RI Scrubber Study/2009-2013 Fuel Budget



Preliminary Screening Results

The levelized costs of energy and overall scorings of the evaluated options are

presented in Table 4.B.20a, Table 4.B.20b, Table 4.B.21a and Table 4.B.21b. All

levelized costs of energy and overall scorings are presented with and without SO2, NOx,

and CO2 price forecasts included. The following figures show the LCOE and total

screening scores.16

Figure 4.B.1 LCOE for Coal Options17

16

4 CSR 240-22.040(2)(B); 4 CSR 240-22.040(2)(B)1 17

4 CSR 240-22.040(2)



Figure 4.B.2 LCOE for Gas Options18

Figure 4.B.3 Total Screening Score for Coal Options19

18

4 CSR 240-22.040(2) 19

4 CSR 240-22.040(2)(C)



Figure 4.B.4 Total Screening Score for Gas Options20

Based on the scoring results, Ameren Missouri selected 10 options to carry forward21.

The 2-on-1 501F based combined cycle options scored highest among the new capacity

options with intermediate dispatch load profiles. The Cheng cycle option ranked high in

large part due to its comparatively low costs of electricity. However, operational and

project development risks pushed their overall scores below that of the combined cycle.

The peaking option rankings favored the larger, 501F combustion turbines over the 7EA

combustion turbine, with the GE LM6000 and Wartsila 20V34SG reciprocating engines

rounding out the list.

The Venice combined cycle conversion will replace CTG Units 3 and 4 from a dispatch

perspective. Modeled as a 2-on-1 combined cycle, the Venice combined cycle

conversion option scored well and appears to offer a low total cost of energy. However,

the prerequisite retirement of Venice Unit 3 and 4 simple cycle units should weigh

heavily when considering other expansion.

As with the Venice combined cycle conversion, the repowering of existing units or the

addition of new units at Meramec will displace existing capacity. The repowering of the

20

4 CSR 240-22.040(2)(C) 21

4 CSR 240-22.040(2)(C); 4 CSR 240-22.040(9)(A)3



Unit 4 STG in a combined cycle or the addition of a new coal unit at Meramec is

assumed to require the retirement of existing Units 1 through 4. Whether the option is to

repower, build a new unit, or rebuild existing units, the result will not necessarily result in

a net capacity increase from the site.

Environmental regulations and permitting strategies that are currently valid will likely

change within the next few years. In light of the current regulatory landscape, natural

gas fueled Meramec repowering options should be given preference over coal fueled

Meramec repowering options. The Meramec options would be subject to extensive

environmental permitting analysis if they were to be considered for further development.

Among the Meramec replacement capacity baseload dispatched options, the Meramec

Unit 3 and 4 boiler replacement and STG rebuild options received the highest scores

except when accounting for CO2 costs. When accounting for CO2 costs, the Unit 4 STG

in a combined cycle conversion ranked highest.

USCPC-Greenfield had the highest overall score among the coal technology options,

and therefore, was passed on as a candidate coal option. The Ameren Missouri team

also wanted to include an unconventional coal technology in addition to the

conventional technology and selected IGCC-Greenfield for further characterization as it

was the highest scoring unconventional coal option. Technologies that incorporated

carbon capture consistently lagged behind their non-carbon capture counterparts even

when accounting for CO2 costs. However, both USCPC and IGCC with carbon capture

were also passed on to the next step in the analysis with their non-carbon capture

counterparts. All other coal resource options were eliminated from further analysis to

keep the options to a manageable size as the four technologies selected would be more

than enough to represent coal supply side technologies.

Power augmentation options appear to score better than the other natural gas

technologies; however, since the capacity addition is much smaller compared to the

others, they were eliminated from further analysis for the purposes of this IRP.

Furthermore, the natural gas resource options that had an overall score lower than that

of the aero-derivative simple cycle (GE LM6000 SPRINT) were not considered for

further analysis.

4.3 Candidate Options

Using the preliminary screening results as a tool, Ameren Missouri selected 10

technologies to be characterized further for modeling and planning efforts. Table 4.B.11

presents a listing of the preliminary candidate options.



Table 4.B.11 Preliminary Candidate Options22

22

4 CSR 240-22.040(2)(C); 4 CSR 240-22.040(9)(A)2



4.4 Supporting Tables

Table 4.B.12 Coal Options – Capacity and Performance



Table 4.B.13 Gas Options – Capacity and Performance



Table 4.B.14 Coal Options – Cost Estimates23

23

4 CSR 240-22.040(1)(E); 4 CSR 240-22.040(1)(F); 4 CSR 240-22.040(1)(G); 4 CSR 240-22.040(8)(B); 4 CSR 240-22.040(8)(C)



Table 4.B.15 Gas Options – Cost Estimates24

24

4 CSR 240-22.040(1)(E); 4 CSR 240-22.040(1)(F); 4 CSR 240-22.040(1)(G); 4 CSR 240-22.040(8)(B); 4 CSR 240-22.040(8)(C)



Table 4.B.16 Coal Options – Commercial Status, Construction Duration and Environmental Characteristics25

25

4 CSR 240-22.040(1)(C); 4 CSR 240-22.040(1)(D); 4 CSR 240-22.040(1)(K)1; 4 CSR 240-22.040(1)(K)3



Table 4.B.17 Gas Options – Commercial Status, Construction Duration and Environmental Characteristics26

26

4 CSR 240-22.040(1)(C); 4 CSR 240-22.040(1)(D); 4 CSR 240-22.040(1)(K)1; 4 CSR 240-22.040(1)(K)3



Table 4.B.18 Coal Options – Economic Parameters and LCOE



Table 4.B.19 Gas Options – Economic Parameters and LCOE



Table 4.B.20a Coal Options – Scoring Results27

27

4 CSR 240-22.040(2)(B); 4 CSR 240-22.040(2)(C); 4 CSR 240-22.040(9)(A); 4 CSR 240-22.040(9)(A)1



Table 4.B.20b Coal Options – Scoring Results28

28

4 CSR 240-22.040(2); 4 CSR 240-22.040(2)(A); 4 CSR 240-22.040(2)(B); 4 CSR 240-22.040(2)(B)1; 4 CSR 240-22.040(2)(C); 4 CSR 240-22.040(9)(A); 4 CSR 240-22.040(9)(A)1



Table 4.B.21a Gas Options – Scoring Results29

29




Table 4.B.21b Gas Options – Scoring Results30

30




4.5 Compliance References

4 CSR 240-22.040(1) ...................................................................................................... 1 4 CSR 240-22.040(1)(A) ................................................................................................. 2 4 CSR 240-22.040(1)(B) ................................................................................................. 3 4 CSR 240-22.040(1)(C) ......................................................................................... 34, 35 4 CSR 240-22.040(1)(D) ......................................................................................... 34, 35 4 CSR 240-22.040(1)(E) ......................................................................................... 32, 33 4 CSR 240-22.040(1)(F) .......................................................................................... 32, 33 4 CSR 240-22.040(1)(G) ..................................................................................... 7, 32, 33 4 CSR 240-22.040(1)(I) ................................................................................................... 8 4 CSR 240-22.040(1)(J) ................................................................................................ 21 4 CSR 240-22.040(1)(K)1 ....................................................................................... 34, 35 4 CSR 240-22.040(1)(K)2 ............................................................................................... 9 4 CSR 240-22.040(1)(K)3 ....................................................................................... 34, 35 4 CSR 240-22.040(1)(K)4 ............................................................................................. 21 4 CSR 240-22.040(1)(L) ................................................................................................ 21 4 CSR 240-22.040(2) ................................................................ 21, 25, 26, 38, 39, 40, 41 4 CSR 240-22.040(2)(A) ................................................................................... 24, 40, 41 4 CSR 240-22.040(2)(B) ................................................................. 23, 25, 38, 39, 40, 41 4 CSR 240-22.040(2)(B)1 ............................................................... 23, 25, 38, 39, 40, 41 4 CSR 240-22.040(2)(B)2 ............................................................................................. 23 4 CSR 240-22.040(2)(B)3 ............................................................................................. 23 4 CSR 240-22.040(2)(B)4 ............................................................................................. 23 4 CSR 240-22.040(2)(C) ........................................................... 26, 27, 29, 38, 39, 40, 41 4 CSR 240-22.040(3) ...................................................................................................... 5 4 CSR 240-22.040(4) ........................................................................................ 13, 14, 19 4 CSR 240-22.040(6) ...................................................................................................... 5 4 CSR 240-22.040(8)(B) ......................................................................................... 32, 33 4 CSR 240-22.040(8)(B)1 ........................................................................... 38, 39, 40, 41 4 CSR 240-22.040(8)(B)2 ........................................................................... 38, 39, 40, 41 4 CSR 240-22.040(8)(C) ......................................................................................... 32, 33 4 CSR 240-22.040(9)(A) ............................................................................. 38, 39, 40, 41 4 CSR 240-22.040(9)(A)1 ........................................................................... 38, 39, 40, 41 4 CSR 240-22.040(9)(A)2 ............................................................................................. 29 4 CSR 240-22.040(9)(A)3 ............................................................................................. 27 4 CSR 240-22.040(9)(D) ............................................................................................... 23



Chapter 4 – Appendix B

Preliminary Screening Analysis ....................................................................................... 1

4.1 Technology Characterization ................................................................................ 2

4.1.1 Capacity Ranges ............................................................................................. 2

4.1.2 Commercial Availability ................................................................................... 3

4.1.3 Capital Cost Estimates .................................................................................... 4

4.1.4 Non-Fuel O&M Costs ...................................................................................... 6

4.1.5 Scheduled and Forced Outages ...................................................................... 7

4.1.6 Waste Generation ........................................................................................... 9

4.1.7 Potentially Useable Byproducts ....................................................................... 9

4.1.8 Coal Technology Options .............................................................................. 11

4.1.9 Natural Gas Technology Options .................................................................. 15

4.2 Preliminary Screening Analysis .......................................................................... 21

4.3 Candidate Options .............................................................................................. 28

4.4 Supporting Tables .............................................................................................. 30

4.5 Compliance References ..................................................................................... 42

chapter 4 - appendix b

Documents